A condensed version of this article will appear in the upcoming 2012 December edition of the Canadian Nuclear Society’s BULLETIN journal.

“The existing coal fleet, though running at vastly reduced levels from previous years, provides the IESO with desirable flexibility, such as quick ramping and operating reserve, under all market conditions. As Ontario’s coal-fired generation is shut down over the next two years, its associated flexibility will be lost. Therefore, future capacity additions should also possess this flexibility to help facilitate the management of maintenance outages, provide effective ramp capability, supply of operating reserve and even provide regulation when necessary”.

This statement appeared as the last paragraph in the “18-Month Outlook from 2012 Sept. to 2014 Feb.” put out by the Independent Electricity System Operator (IESO) on 2012 Sept. 12. Similar comments have appeared in previous 18-Month Outlooks and referenced in the Canadian Nuclear Society’s BULLETIN journal. Coal is very flexible and hydro is as well when allowed to manoeuvre, combined cycle gas turbines and present nuclear, particularly Darlington’s four units, less so (see reference 1). If there is to be any hope for significant nuclear new build in Ontario it must meet this IESO operational requirement. The Enhanced CANDU 6 (EC6) should meet it by its combination of up to 100 percent steam bypass for rapid manoeuvring followed up by relatively slower reactor power changes when the reactor is available to manoeuvre. With a turbine governor system capable of automatic generation control this should permit control of generator output directly from an IESO signal, for automatic or manual grid frequency regulation when operating with steam bypass (see Appendix). France and Germany are more permissive than north America in operating their nuclear power plants and allow the grid operator to change plant output directly, which means reactor power changes since their units do not use steam bypass for load changes. This is equivalent to the IESO directly controlling the output of an existing Ontario unit while in the reactor-following-turbine mode of operation (see Appendix). Potentially the EC6 could be far more manoeuvrable than light water reactor new build in Europe that has to at least meet the flexibility regulations of the European Utilities Requirements (EUR) that are based on the requirements of the grid operators, subject to licensing approval by the specific nuclear regulator. The EC6 would have to comply with the manoeuvrability specifications of the EUR if it wants to be part of new build in Europe. The 100 percent steam bypass capability means that the EC6 will be able to provide full power output much quicker than the poison prevent mode of operation on the existing Ontario units to help restore the grid after a grid collapse since the reactor could remain at full power and the turbine would be supplying house load and be ready to quickly ramp up power when requested by the IESO. This also means zero to 100 percent full power maonoeuvrability capability during normal operation allowing a future Ontario grid to be powered by only clean reliable nuclear and hydro with no fossil fuel (reference 2). Now, how can the existing Ontario units meet the IESO requirements.

The IESO has categorized the output of the eight units at Bruce A and B stations as “flexible nuclear”. This is because Bruce Power has offered up to 300 MWe of manoeuvring capability for each operating unit using steam bypass while holding reactor power constant – presumably because of restrictions in the operating licence on reactor load-following (responding to five minute dispatches from the IESO) and load-cycling (reducing power when demand is low, say overnight and weekends). Even this limited capability comes with limitations that the IESO assumes when moving the nuclear units. Each unit must be curtailed between 100 – 300 MWe; the unit must remain at the reduced power condition for at least three hours; only one unit per station can be curtailed per hour, and any shutdown would last for at least 72 hours. The IESO says that the exact amount of manoeuvring available will vary from time to time based on prevailing technical and regulatory restrictions.

Likely one of the regulatory restrictions on Bruce Power would be the water temperature in the station condenser cooling water discharge duct, set by the Ontario Ministry of the Environment. There are restrictions on the absolute year round discharge temperature and on the temperature difference between forebay intake temperature and the duct discharge temperature with different limits for summer and winter, with a higher differential allowed in winter. When steam bypass is used on a unit with the reactor held at 100 percent full power the cooling water discharge temperature from the unit into the common discharge duct increases, by around 15 percent above normal full power operation for a unit electrical output of 515 MW to grid (the output of a “flexible nuclear” Bruce B unit after dropping 300 MWe to the grid with steam bypass) to a maximum of around 42 percent just supplying house load (around 7 percent of generator output) with zero electrical output to grid, if this mode were viable given the limited capacity of the condensers. One Bruce B unit operating with steam bypass and an electrical output of 665 MW could theoretically supply +/- 150 MW of frequency regulation though this service would normally be shared amongst several generators, and even loads. Cooling water discharge temperature from nuclear power plants was, and still is, an issue in the U.S. even though no different from fossil plants in this regard. Reactors in Europe have had to shutdown or power down in the past when river water temperatures went high.

For any nuclear new build using lake water cooling (and not air cooling) the condenser cooling water discharge duct temperature limits set by the Ontario Ministry of the Environment must not constrain the multi-unit station from providing full electrical manoeuvrability, zero to 100 percent of full station output, when requested by the IESO. The EC6 should be able to achieve this by steam bypass alone at full reactor power if necessary. In the future lake water temperatures may increase as a result of climate change and this should be borne in mind when sizing the unit cooling systems. For a Bruce B unit, reducing reactor power to about 60 percent full power with steam bypass allows unit house-load to be supplied with zero output to grid (poison prevent operation) with a unit condenser cooling water discharge temperature about 84 percent of that at normal full power operation. This means that Bruce B could potentially provide around 3,000 MWe of curtailment to the grid without exceeding cooling water temperature limits if it were allowed to manoeuvre its reactors for load-following, or even load-cycling at night and weekends. However, to ensure that station cooling water discharge temperature limits are not exceeded transiently during simultaneous manoeuvring of several units (an extreme and even unlikely case) might require increasing the steam bypass capacity and beefing up the condenser cooling water systems.

The original Bruce B and Darlington design had the adjuster rods in the core and the intent was to allow load-cycling, not load following, using reactor power changes with no steam bypass but perhaps not to the extent now necessitated by Ontario’s wind heavy grid. For example back in the 1980s several of the Bruce B units experienced nine months of load-cycling including deep (down to 60 percent full power, or lower) and shallow power reductions. Analytical studies based on results of in-reactor testing at the Chalk River Laboratories showed that the reactor fuel could withstand daily and weekly load-cycling. All CANDUs have failed fuel detection and location systems and failed fuel can be replaced while the reactor is at full power. Bruce B and Darlington had a steam bypass system that was designed for only a limited number of turbine trip and loss of grid events so obviously at Bruce A and B it has been upgraded so that it can help to mitigate present day surplus base load generation. In the early reactor operating years the adjuster rods were in the core and could be withdrawn to provide positive reactivity after a spurious reactor trip to bring the reactor rapidly up to about 60 percent of full power with steam bypass to avoid a poison out, poison prevent operation. However revised post trip operating procedures and regulatory oversight resulted in having a reactor poison out after all trips, spurious or otherwise, so adjusters were not needed for rapid recovery after a trip. Since they were not needed for post trip recovery the adjuster rods at Darlington were parked outside the core many years ago to improve fuel burnup during base load operation and presumably Bruce B did the same. Basically the units have been optimized for base load operation at maximum power with very little operating margin for manoeuvring the reactor. Having the adjusters put back in the core and available for manoeuvring will result in reduced fuel burnup and hence higher fuel consumption, however CANDU fuel cost is low. Like the EC6 rapid changes in Bruce B and Darlington electrical output would be done by steam bypass followed up with with slower reactor power changes. Bruce A station does not have adjuster rods but its planned 1,200 MWe of curtailment during periods of surplus base load generation using steam bypass can still be increased, potentially up to 3,000 MWe by adding more condensing capacity, bearing in mind condenser cooling water discharge temperature limits would mean using air cooled condensers. Steam bypass operation effectively reduces fuel burnup.

Although not providing “future capacity additions” the refurbished Bruce B will virtually be a new station and will operate for another 30 years or so before decommissioning or refurbishing and should include the changes necessary to enable the reactor to be manoeuvred to meet the IESO operating requirements for new build. It may not even be necessary for the required changes to be done during refurbishment. They could be started as soon as Bruce Power can get approval for the safety case it will have to make to the nuclear licensing authority, the Canadian Nuclear Safety Commission.

As can be seen the present limited steam bypass on Bruce B is not enough to match the flexibility of the lost coal-fired generation. As an alternative to trying to change the Bruce B reactor licensing conditions with respect to adjusters significant improvement in output power manoeuvring could be achieved by maintaining the reactor at 100 percent full power and increasing the condensing capacity. If a beefed up condenser cooling water system with increased steam bypass is not practical then supplementing the existing condenser cooling water system with a separate air cooled condenser could be an alternative.

Darlington’s four units are not categorized as “flexible nuclear” by the IESO since they take no part in the reduction of surplus base load generation. Darlington electrical output manoeuvres are done without steam bypass and very slowly, since the adjuster rods are parked outside the core, and take considerable time to achieve. Darlington, like the other province owned Ontario Power Generation (OPG) base load suppliers, does not get paid for foregone generation if it were to operate at less than full power to mitigate surplus base load generation. The refurbishments due to start in 2016 should, like Bruce B should, include the changes needed to meet the IESO operating requirements for new generation in Ontario. For this to happen OPG must not be penalized for providing clean greenhouse gas-free flexibility capability and, like Bruce, get paid for foregone generation. The changes could potentially provide around 3,000 MWe of curtailment.

The IESO performance requirement for flexible new generation arises because of the need to integrate the increasing amount of intermittent wind and solar generation that puts grid reliability at risk and the need for dispatchable load-following generation to replace flexible coal. However upgrading Bruce B and Darlington to meet these load-following requirements will enable a reduction in expensive and greenhouse-gas emitting fracked gas-fired generation and ready the grid for a lot more new nuclear (reference 2). Of course such flexibility comes with an additional energy cost from lower fuel burn-up in the case of nuclear but mainly comes from the lower capacity factors and wear and tear that applies to all generation sources to different degrees.

The bottom line is that Ontario’s already “flexible nuclear” can do even better by satisfying IESO requirements to replace flexible coal provided steps are taken now by the Ontario Power Authority and the IESO to enable it. Between Bruce A/B and Darlington there is the potential for around 9,000 MWe of curtailment so this extreme grid flexibility would allow the addition of significant nuclear new build after Darlington B. In the meantime, and although technically, economically and environmentally it makes no sense, the curtailment can make room for wind/solar on the grid.

Appendix – Operating modes of Ontario’s CANDU reactors

When supplying power to the Ontario grid the CANDU units have two plant operating modes, reactor-following-turbine mode and turbine-following-reactor mode. Load cycling was intended to be performed with the unit in the turbine-following-reactor mode. Load following could also have been done in this mode if the units had load following capability as well as in the reactor-following-turbine mode if operation were more stable in this mode. Small power variations, typically +/- 2.5 percent of full power from turbine governor action to stabilize the grid when operating in reactor-following-turbine mode is called primary frequency control and is not load following.

If Ontario’s CANDUs were in reactor-following-turbine plant operating mode they could contribute to grid frequency stability. In the reactor-following-turbine mode of plant operation the steam generator pressure, which will change due to differences in reactor output and turbine-generator output, is kept at its setpoint by changing the reactor power setpoint, using the reactor regulating system, to accommodate changing turbine steam demands in response to grid conditions. Any difference between supply (generation) and demand (load) on the grid shows up as a grid frequency deviation from the nominal 60 Hz. If a unit is operating at 97.5 percent of full power it can provide +/- 2.5 percent power variation automatically by turbine governor action, to help resist the frequency change in concert with other nuclear, hydro, coal and natural gas-fired units on the grid. The more units contributing to this grid stabilization, or primary frequency control, the less the power variation will be on each unit. The designated hydro or coal units, normally hydro, supplying automatic generation control (AGC) service will then return the grid frequency to nominal by removing the frequency offset. Adjusting the turbine governor setpoint to remove the frequency offset is called secondary frequency control, or regulation, and would be performed by the IESO manually or by AGC. Fast acting AGC corrects the seconds to minutes differences in generation and load to balance the grid. The current AGC regulation service requirement from the IESO is for at least plus or minus 100 megawatts at a ramp rate of 50 megawatts per minute but this is being changed to allow other generators and even loads to supply this service. In order to keep the designated unit(s) that is on AGC service in its desired operating range, particularly during the difficult morning ramp-up and the evening ramp-down, other selected coal, gas and hydro units on the grid will be dispatched (load following) at frequent intervals to power up or power down so as to allow the unit(s) on AGC service to do its work of fine tuning the grid balance. The CANDU units were not designed to supply AGC or manual secondary frequency control even though on at least one station provision might have been made for remote control of the turbine governor setpoint by the grid operator when in the reactor-following-turbine mode. If they were designed to supply AGC the CANDUs would have had to operate in the reactor-following-turbine mode.

If the nuclear unit is operating in turbine-following-reactor plant operating mode it makes no contribution to grid stability. In the turbine-following-reactor mode of operation the steam generator pressure is controlled at its setpoint by operation of the turbine governor valve when the reactor power setpoint is changed for any reason. In Ontario the CANDU units operate in this turbine-following-reactor mode, preferred by operators Bruce Power and Ontario Power Generation, and at the maximum allowable power. The operators say this mode gives more stable reactor operation and increases the probability of the unit remaining connected to the grid during major disturbances as well as generating more electricity and more income since the unit does not have to operate at a little less than its maximum output as it would have to do in the reactor-following-turbine mode.

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